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PETROLEUM SOCIETYCANADIAN INSTITUTE OF MINING, METALLURGY & PETROLEUM
PAPER 2002-153
Advanced Techniques for AcousticLiquid Level Determination
J.N. McCoy, O.L. Rowlan, D. BeckerEchometer Company
A.L. PodioUniversity of Texas
This paper is to be presented at the Petroleum Society’s Canadian International Petroleum Conference 2002, Calgary, Alberta,Canada, June 11 – 13, 2002. Discussion of this paper is invited and may be presented at the meeting if filed in writing with thetechnical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will be considered forpublication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to correction.
ABSTRACT
Acoustic liquid level tests are performed successfully
in many different applications throughout the world.
Advanced techniques for acoustic liquid level analysis
are required for wells where unusual conditions exist
such as very shallow liquid levels, annular partial
obstructions, flush pipe, short tubing joints, etc. Some
wells have liners, upper perforations, paraffin, odd
length of tubing joints, poor surface connections and
other conditions which result in an acoustic trace that
may be very difficult to interpret. Normally, the computer
software locates the liquid level and automatically
processes collar reflections to accurately count almost all
of the collars from the initial blast to the liquid level. This
automatic analysis will determine the liquid level depth
for 95% of the wells. However, some wells have
conditions or anomalies that these procedures will not
function as desired. This paper describes special
advanced techniques that can be used to determine the
liquid level in wells with these unusual conditions.
INTRODUCTION
The most common application of an acoustic liquid
level instrument is to measure the distance to the liquid
level in the casing annulus of a well. A single test is
performed on a well to determine the producing
bottomhole pressure. The acoustic signal is digitized and
stored in the computer. The computer processes this
digitized acoustic data to accent collar reflections. The
Total Well Management, TWM, software program
automatically counts the number of collar reflections
from the surface to the liquid level and determines the
liquid level depth. Simultaneously, the casing pressure is
acquired. If gas is flowing up the casing annulus, the
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casing pressure will increase because the casing valves
are closed during an acoustic liquid level depth
measurement. This buildup in casing pressure is utilized
along with well data to determine the casing annulus gas
flow rate. The casing annulus gas flow rate is utilized to
calculate a gradient of the gaseous liquid column above
the pump, if present. Thus, the producing bottomhole
pressure is determined from an analysis of the acquired
data. The producing bottomhole pressure and reservoir
pressure are processed using the Vogel IPR analysis to
present the operator with the producing rate efficiency
and the maximum production rate of the well.
The acoustic instrument can also be applied to depth
measurements inside tubing or other piping. Other
applications include determination of the distance to the
mud or kill liquid level during drilling and work-overs.
The liquid level in a gas lift well can be determined. The
bottomhole pressures in wells with extremely high
surface pressures can be determined. The acoustic
instruments can be used to measure the distance to any
change in cross-sectional area inside pipe or in the
annulus.
The following sections describe the special techniques
for acoustic liquid level determination. In most cases,
once an acoustic trace has been obtained and the liquid
level signal selected, the number of tubing collar
reflections from the surface to the liquid level are counted
in order to calculate its depth. The corresponding number
of tubing joints, multiplied by the average joint length
yields the distance to the liquid level. In other instances
other techniques are required to determine the depth to
the acoustic obstructions.
WELLHEAD ATTACHMENTS
Acoustic liquid level instruments were developed in
the 1930's. An acoustic wellhead attachment is connected
to an opening at the surface of a well. The acoustic
wellhead attachment consists of an acoustic pulse
generator, a microphone and optionally a pressure gage.
The technology for generating the acoustic pulse was
originally explosive materials such as a dynamite cap, 45-
caliber blank, or 10 gauge black powder blank. Pulse
generating technology improved by attaching a volume
chamber to the acoustic wellhead and generating the
acoustic pulse with a sudden release of a gas into the well
(compression gas pulse) or by releasing gas from the well
into the volume chamber (rarefaction gas pulse). The
explosive dynamite caps and blanks are a safety hazard
and have resulted in damage to wells and environment.
While these explosive sources should not create a
problem if the casing annulus contains only hydrocarbon
gas, major explosions have occurred when oxygen was
allowed to enter the casing annulus and the
oxygen/hydrocarbon mixture was ignited.
The versatility, economy and convenience of gas guns
have resulted in widespread use of this type of acoustic
pulse generator. Sudden expansion of gas from a volume
chamber into the well generates the acoustic pulse. In
most cases, compressed CO2 or N2 gas is loaded into the
volume chamber, which is charged to a pressure greater
than the well pressure. A valve in the wellhead
attachment is opened rapidly, either manually or
electrically, resulting in a pressure pulse being generated
in the casing annulus gas. The acoustic pulse travels
through the gas in the casing annulus and is partially
reflected by changes in cross sectional area. The
remaining pulse energy is then reflected by the gas/liquid
interface at the depth of the liquid level. The reflected
signals travel back to the surface of the well where they
are detected by the microphone.
The microphone within the wellhead attachment
converts the reflected acoustic signal into an electrical
signal consisting of a series of pulses, which correspond
to the sequence of reflections. The microphone must
operate over a wide pressure range from a vacuum to the
maximum pressure that exists in the wells being tested.
Good microphones are designed to cancel the mechanical
vibrations of the wellhead while remaining sensitive to
the acoustic signal reflections.
STRIP CHART RECORDING OF ACOUSTICSIGNALS
One manual1 method for processing the acoustic signal
is to record the reflected signal on a paper strip chart, for
analysis purposes the acoustic signal must be amplified
and filtered, and then recorded. An amplifier/recorder
filters and amplifies the electrical signal from the
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microphone and records the enhanced signals on a paper
strip chart. Modern instruments use analog to digital
converters and microprocessors to improve the signal
quality and print the chart. The frequency content of the
reflected acoustic signals varies depending on the
characteristics of the initial pulse, the pressure in the gas,
the distance traveled and the type of cross sectional area
change. In general, as the pulse travels in a gas, the
amplitude of the signal decays. The high frequency
energy decays more rapidly than the low frequency
energy. Thus, the acoustic response from the collars at
the top of the well contains high frequency energy, the
response from deep collars contains medium frequency
and the signal from the liquid level is mostly low
frequency energy. This is especially apparent in deep
wells with low casing pressure. Fluid level instruments
are designed to include various filters, which can be used
to accent signals that correspond to these frequency
ranges. One enhancement in recorder technology has
been to record the signals on the dual channels2. One
channel is tuned to higher frequencies from the collars
while the second channel is tuned to low frequencies
from the liquid level. Single channel instruments can be
operated in any of these modes and it is possible to
switch from one frequency response to another while the
instrument is recording. Initially, the single channel
instrument is operated in the collar mode (high or
medium frequency), which is then switched to the liquid
level mode (low frequency) when the collar signal fades.
Switching may be manual or automatic.
COMPUTER PROCESSING OF ACOUSTIC DATA
The reflected electrical signal from downhole
anomalies can be digitized and stored in a computer for
more accurate analysis. Five important achievements are
made possible by utilization of a portable laptop
computer. First, the acoustic signal is recorded at the
optimum resolution of the analog to digital converters
and is not limited to the resolution of the trace printed on
a strip of paper. The high resolution processing available
using a computer is displayed in Fig. 1, where the
acoustic signal of a plunger falling past the 81st tubing
joint (which corresponds to a 0.04 psig pressure pulse) is
recorded. Second, the computer can utilize digital
processing of the acoustic data to automatically obtain
accurate liquid level depths. Third, the determination of
bottom-hole pressures from the acoustic liquid level
measurement, the surface pressure, and properties of the
produced fluids is automatically available. Fourth, the
computer offers unattended operation of the equipment in
that the computer can be programmed to perform well
soundings and obtain casing pressure measurements on
command, without monitoring by an operator. Fifth, well
data can be stored and managed efficiently and accurately
in conjunction with the acquired acoustic and pressure
data. The processing speed of current laptop computers
allows instant analysis of acoustic liquid level trace, well
performance, transient pressure and pumping
performance, immediately at the well as soon as the data
is acquired.
A laptop computer permits an operator to
automatically obtain acoustic liquid level data and
surface pressure measurements from which bottom-hole
pressures can be calculated. A long term pressure buildup
and/or draw down test in pumping wells can thus be done
inexpensively. Pressure buildup data permits the operator
to obtain reservoir properties such as permeability, skin
damage, reservoir pressures and numerous other
parameters at a relatively low cost.
PROCESSING OF ACOUSTIC DATA
Normally, the computer software locates the liquid
level and then processes collar reflections between one
and two seconds from the beginning of the acoustic blast
to obtain the reflected collar frequency rate. Centered at
the collar frequency a narrow band-pass filter processes
the acoustic data and the program will automatically
attempt to count all of the collars from the initial blast to
the liquid level. The depth to which collars are counted
should be as close to the liquid level as possible. If the
depth to which collars are counted is not at least past 80%
of the distance to the liquid level, then the shot should be
repeated with an increased chamber pressure in order to
improve the signal to noise ratio. The automatic analysis
will determine the depth to the liquid level for 95% of the
wells. Some wells will have an acoustic trace that may be
very difficult to interpret, because of the presence in the
wellbore of liners, upper perforations, paraffin, odd
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length of joints, poor surface connections and other
conditions. In these 5% of the wells having these
conditions or anomalies that the automatic procedure
does not function as desired, then advanced techniques
should be used to determine the depth to the liquid level.
DOWNHOLE MARKER
When the lengths of tubing joints vary considerably, so
that an average joint length is not representative, some
operators have placed an over-sized tubing collar
(marker) to serve as an acoustic reflector at a known
reference depth. When other acoustic reflections are
identified on the acoustic trace, such as those generated
by gas lift mandrels, liner tops, crossovers where the
tubing diameter changes, tubing anchors, perforations;
the known depth of these anomalies can be used to
calculate the depth to the deeper liquid level. This
technique is to locate a movable indicator on a marker
such as the tubing crossover, when the liquid level is
below the tubing crossover. The operator places the
movable indicator on the top of the known tubing
crossover and specifies the number of joints (or the
distance) from the surface to the acoustic reflector. The
program will automatically calculate the distance to the
indicator located at the liquid level or other anomaly of
interest by comparing the ratio of elapsed times on the
acoustic trace to a ratio of their depths. For example Fig.
2 shows an anomaly detected in the annulus above the
liquid level, as indicated by a strong reflected rarefaction
(up kick) acoustic pulse recorded at 6.507 seconds. The
anomaly was displayed at the same time in all acoustic
traces collected while testing the well. The depth to the
anomaly corresponds to the increase in area of the
annulus volume at the depth of 4015.92 feet at the
crossover from the 2 3/8 inch diameter hydril to the 1.90
inch diameter hydril collar-less tubing. A strong reflected
compression (down kick) acoustic pulse recorded at
14.827 seconds indicates the depth to the top of the liquid
level is 9150 feet (14.827/6.507*4015.92 = 9150) from
the surface.
SHALLOW LIQUID LEVEL
When the fluid level is very close to the surface, such
as in shut-in wells with high bottom hole pressure or
most water supply wells, the recorded acoustic signal will
include a large number of multiple fluid level signals
(repeats). The initial signal reflected from the liquid level
may be hidden in the high amplitude of the acoustic blast
released from the gun. Determination of the liquid level
depth may be affected by the presence of the high
amplitude and low frequency signal from the liquid level.
Less pressure should be used in the gas gun in cases
where high fluid levels are encountered, because the
amplitude of the acoustic signal may be driven off scale.
If the round-trip travel time between the surface and the
liquid is less than 1.0 seconds, it is difficult to pick the
liquid level automatically. On shallow liquid levels the
operator may be required to move the liquid level
indicator manually. The liquid level indicator can be
moved in increments and the operator can position the
indicator on the liquid level to determine the round-trip
travel time.
MEASURE ANNULAR GAS FLOW
Measurement of annular gas flow rate in the field
usually requires using a portable tester or installing a
separate flow line from the casing annulus to the test
facility. This costly process can be avoided by estimating
the gas flow rate from a short casing pressure buildup
test3. The procedure for this test is to close the casing
valve, as fluid continues to be produced up the tubing.
Free gas at the pump intake bubbles up through the
gaseous liquid column above the pump intake and
collects in the known annular volume between the casing
and tubing. The change in casing pressure with respect to
time is recorded. The annular gas flow rate is calculated
from the annular volume and pressure buildup rate.
DURATION OF CASING BUILDUP TEST
The importance of the length of time the casing valve
is closed and the effect of closing the casing valve on a
well’s production rate is shown on Fig. 3. Multiple
surface dynamometer cards (9.68 strokes per minute)
were collected immediately after the casing valve was
closed. An improved collar size downhole gas separator
is installed in this well and a gaseous liquid column of 79
feet was measured above the pump intake, contributing
7.2 psig to the pump intake pressure. The annular gas
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flow rate of 72 MCFD was determined from 1.5 psig per
minute casing pressure buildup rate. The recommended
length of time for the casing pressure buildup test is 2
minutes. After the casing valve had been closed in for 5.9
minutes and the casing pressure increased 8.8 psig, the
57th surface dynamometer card displayed a sudden
change in shape as the increasing casing pressure
temporally stopped flow from the reservoir into the well
bore and forced the pump into complete fluid pound
conditions. For acoustic liquid level surveys, if the
gaseous fluid level is being maintained at or near the
pump intake, the action of the operator of closing the
casing valve can impact the steady state operation of the
pump. Therefore, the operator should only close the
casing valve for a short time period and the casing valve
should be reopened after the casing pressure buildup test
is complete. The operator should allow a period of time
to pass before performing an additional test. This time
will allow the conditions at the pump to return to the
steady state conditions existing prior to acquisition of an
acoustic liquid level survey. Note, that very accurate
casing pressure measurements are necessary for a short
term (2 minutes) casing pressure buildup test.
WALKER FLUID LEVEL DEPRESSION TEST
C.P. Walker4, 5 developed a process for determining
the producing bottomhole pressure in wells that have
gaseous liquid columns. The Walker Fluid level
depression test is used for wells producing some gas from
the annulus. The procedure consists of determining the
pressure at the gas/liquid interface at normal operating
conditions. Then, the casing pressure is increased by use
of a backpressure valve and stabilized. When the liquid
level is stable, the gas/liquid interface pressure is
determined at the lower liquid level depth. The height of
the gaseous liquid column is plotted on the vertical axis
versus the gas/liquid interface pressures plotted on the
horizontal axis forming a straight line. The pump intake
pressure is the extrapolated gas/liquid interface pressure
where the height of the gaseous liquid column is zero (0)
at the pump intake depth.
The Walker procedure can be modified6 in high rate
wells (where depressing the fluid level by closing the
casing valve and letting gas accumulate in the annulus)
without using a backpressure valve to stabilize the casing
pressure. The acoustic liquid level device is used to
determine the pressure at the top of the gaseous liquid
column periodically as the closed in casing pressure
builds up. This modified Walker procedure can be used to
determine the pump intake pressure in high rate ESP
lifted wells and verify that the downhole pressure sensor
is operating properly. Using this technique, Fig. 4 shows
the pressure at the gas/liquid interface extrapolated to 936
psig at the pump intake, which confirms the output of
well 5529 ESP sensor reading of 883 psig. The results
from the modified Walker method give the most accurate
calculation of pump intake pressure when the liquid level
is pushed down "close" to the pump intake. One
advantage of the test is to minimize possible error from
estimating the gradient of the liquid column above the
pressure sensor. The operator performing the test needs to
monitor the fluid level periodically so as not to drive the
fluid level to the pump intake and create a "pumped-off
condition". In low PI wells, errors are usually introduced,
if pushing the liquid level down toward the pump
displaces casing fluid into the pump and restricts flow
from the formation. In low PI wells, the best results are
obtained6 when a backpressure regulator is used and time
is allowed to pass until the gaseous liquid column
stabilizes between fluid level shots.
GASEOUS LIQUID COLUMN GRADIENTCORRECTION
As shown by the Walker Fluid Level Depression test,
when a gaseous liquid column exists in the annulus of a
well producing at stabilized conditions, the pressure at
any depth in the gaseous liquid column is independent of
the surface pressure. The producing bottom hole pressure
and pump intake pressure remain unaffected by the
changes in surface casing pressure and liquid level as
long as the production rates through the tubing and casing
annulus remain constant. The Echometer gaseous liquid
column gradient correction curve3 shown in Fig. 5 was
obtained from extensive field tests using Walker’s
method. With one acoustic fluid level measurement and
use of this curve, the operator can rapidly determine the
pressure contributed from the gaseous liquid column to
the pressure in the casing annulus.
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Using this technique to determine the pressure exerted
by a gaseous liquid column, the operator should close the
casing valve and continue to pump the well. Immediately,
an acoustic liquid level test should be taken to determine
the depth to the top of the gaseous liquid column (L). The
well should be pumped with the casing valves closed for
approximately 2 minutes. The increase in casing pressure
(dP) and the time period (dT) during the increase in
casing pressure is recorded. Using the value of L x dP/dT
and Fig. 5, the operator determines the value of Fg, the
approximate fraction of gas present in the liquid column.
Multiplying Fg times Hp (or the gaseous liquid column
height) determines the equivalent amount of gas in the
gaseous liquid column. Add this equivalent height of gas
in the gaseous liquid column to the gas column length (L)
to obtain Da. Da is the distance from the surface to the
gas/liquid interface, if the gaseous liquid column were
separated. Again using Fig. 5 and the value of Da x
dP/dT determine fo, the effective oil fraction. The
effective oil fraction, or gradient correction factor, should
be multiplied by the gradient of the gas free oil to
determine the gradient of the gaseous liquid column.
Multiplying the height of the gaseous liquid column by
the gradient of the gaseous liquid column determines the
pressure exerted by the gaseous liquid column.
LIQUID LEVEL TRACKING
A liquid level tracking test is defined as the process of
automatically monitoring the position of the liquid level
in a well for a time period at a user specified frequency.
The test is usually performed using the Well Analyzer
and the Remote Fire gas gun. These components are
controlled by software to perform acoustic well
soundings on a scheduled basis without operator
attention. The computer-based acoustic measurement
system records depths to the liquid level at user selected
specific time intervals, as short as once a minute.
Automatically, the system acquires the liquid level data,
determines depth to the liquid level, and displays the
position of the liquid level. Then it checks whether the
liquid level is within given depth limits and generates an
electrical signal when the specified limits are exceeded.
Fig. 6 shows the flexibility available to the user in
specifying the liquid level tracking alarm limits. The
electrical signal from the relay is used to alarm the
operator that a liquid level is outside a specific range and
a limit has been exceeded. The relay alarm signal could
be used to sound an alarm horn or to operate a switch to
power off or on an electric motor controlling a pump.
Liquid Level tracking has numerous applications in
drilling, workover, completion, and production
operations. Some examples of these applications are: 1)
Monitoring fluid level in offshore risers, 2) Monitor fluid
level while drilling with no returns7, 3) Keeping fluid
level within limits to minimize formation damage, 4)
Monitoring position of batch treatments, 5) Following
progress of continuous unloading of a gas lift well, 6)
Controlling the electric motor on a Progressive Cavity
pump to maintain a liquid level above the pump, and 7)
Acquiring a permanent record of fluid levels during a
critical test or operation. The ability to monitor the liquid
level improves the operator’s ability to safely and
efficiently control his operations.
PRESSURE TRANSIENT DIGITAL DATAACQUISITION
A digital pressure transient data acquisition and
processing system8 uses an acoustic liquid level
instrument to determine the annular fluid distribution and
the producing bottom hole pressure. Unattended remote
operation is possible by using a laptop computer and data
acquisition software to control the taking of fluid level
shots according to a predefined schedule for an extended
buildup or draw down test. Bottom hole pressures are
automatically determined and the various types of
pressure transient analysis are presented to the operator in
real time. Fig. 7 is an example plot a Horner pressure
transient analysis.
A well should be producing at steady state conditions,
prior to shutting in the well for an extended buildup test.
Shutting in the well to install a dowwnhole pressure
bomb can disturb the steady state conditions of a well.
The presence of artificial lift equipment installed in a
well usually prevents installation of a pressure bomb in
the bottom of the well, without shutting down the well
and pulling the artificial equipment. The process of
shooting fluid levels and measuring the casing pressure
allows the determination of bottomhole pressure and
7
eliminates the need to pull the artificial lift equipment.
Data can be acquired as soon as the well is shut in.
Analysis at the well site can be done to determine if
enough data has been acquired for a complete analysis of
the well.
RATE OF FILL-UP
When determining the depth to the liquid level on a
well, the recommended practice is to acquire two acoustic
liquid level shots on the same well. The two acoustic
traces should repeat and downhole reflectors should
appear at the same elapsed times on the traces. If the
acoustic traces do not repeat or the liquid level is not
obvious, then the liquid level should be moved. The
liquid level can be identified as the downhole reflector
that will move. A high liquid level on an acoustic test can
be depressed by increasing the casing pressure, if casing
gas is produced. Turning off the pump on a well
producing only liquid will cause the liquid to rise.
Shutting down a well producing only liquid will cause
a rise in the liquid level in the casing annulus. When
shutting down a well, the fill-up rate will depends upon
the producing rate of the well and the annular area of the
casing. A fill-up chart for various production rates in
different sizes of pipe is shown in Fig. 8. The rate which
liquid initially fills the casing annulus is shown on the
chart. As liquid enters the wellbore the fill-up rate
decreases and the bottom hole pressure increases as the
height of liquid exerts increasing backpressure on the
formation. If the well is producing gas up the casing
annulus, the rate of fill-up is not as predictable. A casing
pressure build-up rate in excess of 0.3 psi/minute
indicates that the casing annulus liquid contains a
substantial amount of free gas and the fill-up data should
be used with caution.
OTHER METHODS TO DETERMINE ACOUSTICVELOCITY
Another technique to determine the distance to the
liquid level is for the operator to input the acoustic
velocity and then measure the acoustic roundtrip travel
time to the liquid level. The velocity can be obtained
from prior data obtained in the field, from plots of
acoustic velocity, from a gas analysis, or calculated from
a computer program that uses gas properties or
composition. Echometer Company provides free of
charge downloads of a paper9 from the Internet that
displays the acoustic velocity of various hydrocarbon
gases at various pressures and temperatures. Also, the
acoustic velocity can be determined from a sample of gas
obtained from the casing annulus. The sample of gas can
be collected into a tube of known length, and the acoustic
velocity of the sample of gas can be determined from a
measured acoustic pulse travel time in the tubing. The
acoustic velocity of the gas that was determined at
surface conditions should be adjusted for the changes in
pressure and temperature that occur in the well. This
technique is reasonably accurate only if the well
continuously vents gas from the annulus so that the
sample of gas at the top of the well is representative of
the composition of the gas in the annulus. This procedure
should not be used on most shut-in wells since different
gases tend to separate with the lighter gases rising to the
surface. After the acoustic velocity is determined or
estimated, the acoustic wave round-trip travel time from
the initial pulse to the liquid level reflection is read
directly from the acoustic trace. The round-trip travel
time is divided by two and multiplied by the acoustic
velocity to calculate the depth to the liquid level.
When the specific gravity or the composition of the
gas is accurately known, then the velocity of sound in the
gas can be calculated. Free of charge software programs,
AWP200010 and TWM11, provide the operator the ability
to select from four options to calculate the acoustic
velocity at a known pressure and temperature using: 1)
gas specific gravity, 2) gas composition analysis, 3) depth
markers, or 4) tubing joint collar reflections.
PRESENCE OF CO2 IN CASING GAS
Fig. 9 compares the gradients of various components
(oil, CO2 and 0.85 SG hydrocarbon gas) that are found in
the casing annulus of some CO2 flooded oil wells. The
presence of large percentages of CO2 in the annular gas
requires that special attention be given to the acquisition
of acoustic fluid levels and to the calculation of the pump
intake pressure. At low pressures, the CO2 behaves as a
hydrocarbon gas, and the CO2 gas column pressure can
be calculated accurately. At flowing bottomhole
8
pressures in excess of 1000 psi and temperature in the
range of 100 degrees F, the density of CO2 increases
rapidly and approaches the density of 35 degrees API
hydrocarbon liquids. The CO2, oil and water may
become miscible, and this mixing of the fluids will result
in difficulties in detecting the acoustic gas/liquid
interface reflection since a distinct interface does not
exist. From 600 psi to 1400 psi, rapid changes in CO2
density can make the fluid gradient below the gas/liquid
interface difficult to determine, since the phases are
becoming miscible, and other techniques such as the
Walker method may need to be employed. As the flowing
bottomhole pressure increases above 1500 psi, the
miscibility characteristics of CO2, oil and water usually
result in relatively little gas being produced up the
annulus, even though large volumes of gas are produced
through the tubing and pump, and are observed at the
surface as large Gas/Oil ratios. At the pump intake, the
CO2-oil mixture behaves essentially as if it were mostly
oil, and the presence of CO2 in the miscible phase instead
of a gas phase increases the pump efficiency.
CONCLUSION
Technology for acoustically determining the depth to
the liquid level is continually evolving and is improving
the accuracy of acoustically determined downhole
measurements, including distances and bottomhole
pressures. Normally, the computer software automatically
locates the liquid level and processes tubing collar
reflections to accurately determine the number of collars
reflections from the surface to the liquid level. Downhole
distances and pressures are calculated automatically.
Advanced techniques for acoustic liquid level analysis
are required for wells where unusual conditions exist.
There are many difficult or abnormal wells where
advanced techniques can be used to determine the liquid
level in these wells. Acoustic liquid level well sounding
is used successfully in almost all possible applications
throughout the world and its applications continue to
expand.
The advent of portable computers and software has
made analysis and acquisition of acoustic well soundings
easier, faster, and more accurate. Use of a portable
system permits further in-depth well and reservoir
analysis by acquisition and analysis of acoustic data,
while unattended; for example, permitting liquid level
tracking and pressure transient data acquisition and
analysis.
REFERENCES
1 . McCoy, J.N., Becker, Dieter, Podio, A.L., and
Drake, B., “Improved Analysis of Acoustic Liquid
Level Depth Measurements Using Dual Channel
Analog/Digital Strip Chart Recorder” presented at
the Southwestern Petroleum Short Course, Lubbock,
Texas, 1997.
2 . McCoy, J.N., Podio, A.L. and Huddleston, K.L.:
“Analyzing Well Performance XV,” presented at the
1987 Artificial Lift Workshop, Houston, TX, Apr.
22-24.
3 . McCoy, J.N., Podio, A.L. and Huddleston, K.L.:
“Acoustic Determination of Producing Bottomhole
Pressure,” paper SPE 14254 presented at the 1985
SPE Annual Technical Conference and Exhibition,
Las Vegas, NV, Sept. 22-25.
4. U.S. Patent No. 2,161,733, C.P. Walker, Method of
Determining Fluid Density, Fluid Pressure and the
Production Capacity of Oil Wells. Date issued, June
6, 1939.
5. Walker, C.P., "Determination of Fluid Level in Oil
Wells by the Pressure-wave Echo Method,"
presented at the Los Angeles Meeting, October,
1936, Transactions of AIME, 1936.
6 . McCoy, J.N., Podio, A.L., Rowlan, Lynn and
Garrett, Mark, "Use of Acoustic Surveys for Field
Calibration of Surface Readout BHP Gages in ESP
Installations," SPE 37452, presented at the SPE
Production Operations Symposium, in Oklahoma
City, Oklahoma, March 9-11, 1997.
7 . Schubert, J.J. and Wright, J.C.: “Early Kick
Detection Through Liquid Level Monitoring in the
Wellbore,” presented at the 1998 IADC/SPE Drilling
Conference held in Dallas, Texas 3-6 March 1998.
8. McCoy, J.N., Podio, A.L. and Becker, D.: “Pressure
Transient Digital Data Acquisition and Analysis
9
From Acoustic Echometer Surveys in Pumping
Wells,” paper SPE 23980 presented at the 1992 SPE
Permian Basin Oil and Gas Recovery Conference,
Midland, TX, Mar. 18-20.
9. McCoy, J.N., “Acoustic Velocity of Natural Gas”,
www.Echometer.com\papers\nat_gas.html
10. Echometer Company, “Download AWP2000
Software”,
www.Echometer.com\software\index.html
11. Echometer Company, “Download TWM Software”,
www.Echometer.com\software\index.html
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Fig. 1 – High Resolution Processing of Acoustic and Pressure Signal.
Fig. 2 – Known Depth of Downhole Marker determined Depth to Liquid Level.
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Fig. 3 – Change in Steady State Conditions Caused by Closing Casing Valve.
Fig. 4 – Gaseous Liquid Column Height vs. Pressure at the Gas/Liquid Interface
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Fig. 5 – Echometer Gaseous Liquid Column Gradient Correction Curve
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Fig. 6 – User Specified Liquid Level Tracking Alarm Limits.
Fig. 7 – Pressure Transient Analysis with Horner Analysis Plot.
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Fig. 8 - Fill-up Rate for Various Production Rates in Different Sizes of Pipe
Fig. 9 - Comparison of Oil, CO2 and 0.85 SG Hydrocarbon Gas